CALGARY, ALBERTA–(Marketwired – Nov. 12, 2015) – Rock Energy Inc. (TSX:RE) (“Rock” or the “Company”) is pleased to report its financial and operating results for three and nine months ended September 30, 2015.

Copies of Rock’s audited financial statements and related management’s discussion and analysis for the three and nine months ended September 30, 2015 have been filed on the SEDAR website at www.sedar.com and may be obtained on Rock’s website at www.rockenergy.ca.

Rock is a Calgary-based crude oil exploration, development and production company.

CORPORATE SUMMARY

FINANCIAL

Three Months Ended
September 30,

Nine Months Ended
September 30,

2015

2014

2015

2014

Crude oil and natural gas revenue (‘000)

$14,530

$32,995

$50,214

$102,858

Funds from operations (‘000) (1)

$9,781

$16,677

$24,435

$51,268

Per share – basic

$0.21

$0.41

$0.53

$1.29

– diluted

$0.20

$0.40

$0.52

$1.23

Net income (loss) (‘000)

$7,944

$3,829

($3,513)

($5,178)

Per share – basic

$0.17

$0.10

($0.08)

($0.13)

– diluted

$0.17

$0.09

($0.08)

($0.13)

Total net capital expenditures (‘000)

$8,626

$39,532

$33,819

$74,425

As at
September 30, 2015

As at
September 30, 2014

Net debt (‘000) (1)

$63,391

$39,433

Common shares outstanding

47,475,913

40,374,997

Options outstanding

3,990,832

3,094,981

OPERATIONS

Three Months Ended
September 30,

Six Months Ended
September 30,

2015

2014

2015

2014

Average daily production

Crude oil and natural gas liquids (bbls/d)

3,807

4,531

4,198

4,628

Natural gas (mcf/d)

757

1,293

906

1,503

Barrels of oil equivalent (boe/d)

3,933

4,747

4,349

4,879

Average product prices

Crude oil and natural gas liquids ($/bbl)

$40.96

$77.85

$43.15

$79.70

Natural gas ($/mcf)

$2.63

$4.54

$3.05

$5.33

Total ($/boe)

$40.15

$75.56

$42.29

$77.25

Operating netback ($/boe) (2)

$23.17

$40.63

$21.98

$42.75

(1) Funds from operations and net debt are considered additional-GAAP measures; Refer to the “Additional-GAAP Measures” section at the end of this MD&A.

(2) Operating netback and total net capital expenditures are considered Non-GAAP measures; Refer to the “Non-GAAP Measures” section at the end of this MD&A.

(3) Operating netback exclude realized hedging gains of $8.14 and $2.48 per boe, respectively for the three and nine months ended September 30, 2015 (2014 – hedging losses of $0.11 and $1.28 per boe, respectively).

LETTER TO THE SHAREHOLDERS

Dear Shareholders,

Commodity prices during the last twelve months have had a significant effect on the global oil and gas industry including Rock. The last year has clearly demonstrated that supply has been larger than demand and global inventories have been built. The price response has communicated this imbalance to the industry and significant capital programs have been cancelled around the world.

One of the first places to see this evidence is in the US rig count, and in the last 12 months the US rig count has dropped from 1,600 to less than 600. The next place to watch is how the reduction in rig counts affects production levels. In the last 6 months US production has dropped by over 600 thousand bbl per day. These are clear signs that the market is working. Higher cost, less economic projects are being cancelled. That being said, the world still consumes 95 million bbls per day of oil, and demand is growing at 1.0 – 1.5 million bbls per day. Current strip pricing cannot attract enough capital to replace declines and satisfy the growth in consumption over the long term with reasonable economic rates of return.

Looking ahead to 2016, prices are not likely to improve until inventories have been consumed. External forecasts are predicting the inventory reduction to occur resulting in an increase in oil prices during the second half of next year. At Rock, we have forecast guidance using forward strip pricing (WTI = $50.00 US/bbl) for next year as we plan our base budget. Once inventories begin to decline, and prices begin to respond we can consider a more robust capital spending plan.

The other factor that we need to address is costs. At Rock we have already made changes to our administration costs by reducing our staffing level by 20%. Though these decisions were very difficult given the people and relationships involved, it was necessary for the organization in light of the environment we are operating in. We are also working hard to continue to reduce both our operating and capital costs and have already made progress in these areas. We will continue to focus on this as we move into 2016.

The team at Rock has been focused on building an asset base with a low decline rate (15% – 20%) so that the assets could be maintained with minimal capital spending. Our base 2016 plan would generate $25 million in funds from operations assuming strip pricing (WTI $50.00 US/bbl). We plan to invest $18 million next year to hold our production flat, with the remaining $7 million we plan to test a few exploration ideas ($2 million) and allocate the remaining funds to pay our debt down ($5 million). If we were to spend all our funds from operations drilling oil wells, and not increase our debt, we could grow our production by over 15%.

This is a time for careful disciplined allocation of capital, not a race for production growth. This is a time to build our inventory of opportunities.

I thank you for all your support in these turbulent times, but rest assured our objectives are aligned as shareholders and your Company is in a solid position.

Sincerely, and on behalf of the Board of Directors:

Allen J. Bey, President and Chief Executive Officer

REPORT TO SHAREHOLDERS

During the third quarter of 2015 Rock was able to demonstrate significant positive responses from the enhanced oil recovery (“EOR”) project at Mantario/Laporte, discovered an extension to the north west edge of the pool at Laporte, completed another delineation phase of the Viking light oil pool at Onward and took significant steps to reduce both our operating and general and administrative cost structures.

The quarter was highlighted by the following specific accomplishments:

Drilled 2 (2.0 net) wells at Laporte to confirm the extension of the main pool to the north west;

Averaged 3,933 boe per day (97% crude oil and liquids);

Completed the conversion of 2 more injection wells at the EOR facility at Mantario/Laporte as part of the overall EOR project;

Divested of conventional heavy oil properties at Lloydminster with no production for net proceeds of $0.4 million, including 32 well bores;

Total net capital expenditures during the quarter were $8.6 million;

Generated net income of $7.9 million ($0.17 / basic share); and

Generated funds from operations for the quarter of $9.8 million ($0.21 / basic share).

Rock’s realized price in the third quarter of 2015 was $40.15 per boe compared to $50.38 per boe in the second quarter of 2015 and $75.56 for the same period a year ago. The decrease in price realization is primarily attributed to a decrease in WTI pricing (WTI decreased from $57.94US/bbl in the second quarter of 2015 to $46.38 US/bbl).

Operating costs decreased during the quarter to $14.41 per boe compared to $18.63 per boe in the second quarter of 2015 due to lower transportation costs and prior period adjustments.

Rock generated an operating netback of $23.17 per boe in the third quarter of 2015 compared to $27.55 per boe in the second quarter of 2015, which were negatively impacted by deterioration in product pricing. Hedging gains excluded from operating netbacks were $8.14 per boe in the third quarter.

Total net capital expenditures for the third quarter of 2015 were $8.6 million, including $5.3 million for the drilling program, $2.7 million for facilities, $1.0 million for land, seismic, and capitalized G&A, offset by $0.4 million of net proceeds from the sale of heavy oil properties in Lloydminster. Total net debt at the end of the quarter was $63.4 million against bank lines of $80.0 million, or 1.6 times debt to third quarter funds from operations annualized.

Rock’s daily production for the third quarter of 2015 averaged 3,933 boe per day (97% oil and liquids). For the month of October, the Company produced approximately 3,800 – 4,000 boe per day.

Mantario/Laporte, Saskatchewan

During the third quarter of 2015 Rock was able to make significant progress in managing the production and reservoir response at the Laporte EOR project. Gas/Oil ratios have stabilized and begun to decline in portions of the pool where polymer injection has been established, pool water cuts are within expected levels, and we have observed positive pressure responses at producing wells. Production from the pool has stabilized in the 2,300 – 2,500 bopd for the last 8 months which is approximately 600 bopd higher than the pool would be producing if the EOR scheme had not been implemented. The flood is working. Going forward, we will continue to convert a few more producers (as necessary) to ensure optimum sweep efficiency, pressure maintenance and maximum recovery factor. Once the pressure maintenance plan has been completed Rock will review the need to drill additional infill locations to complete the drainage pattern. For 2016 we are forecasting the pool to average 2,200 – 2,400 bopd net of downtime (spring break-up etc.).

During the quarter Rock drilled 2 (2.0 net) wells to test the potential extension of the pool to the North West. One well was cased and put on production, one well was classified as dry and abandoned. These wells were successful in confirming the pool does extend out into the adjoining lands. To date in the fourth quarter, we have drilled an additional 3 (3.0 net) wells following up on the pool extension and testing a new exploration prospect. The two extension wells are being completed and put on production, the exploration well is currently being evaluated. The plan for 2016 is to continue to validate the extension, apply for an expansion to our EOR project, and then develop the reservoir within the EOR royalty regime.

Onward, Saskatchewan Viking

During the third quarter of 2015, the Company drilled an additional 5 (5.0 net) Viking horizontal oil wells at Onward to complete another phase of delineation for the pool.

Total production from the Viking during the third quarter averaged 950 bopd. Viking production is currently averaging approximately 800 – 850 bopd from 61 wells of the 65 wells drilled to date. The four drilled and uncompleted wells are planned to be brought on stream during the first quarter of 2016.

During the quarter the Company made more progress in reducing capital costs and was able to achieve an average total cost to drill, case and complete a Viking well of $700k, equipping the well adds $125k for a total on-stream cost of $825k (a 25% – 30% reduction from 2014). The Company believes further cost reductions can be achieved, and is focused on that for any future Viking drilling in 2016.

2015 Guidance

Given the current level of crude oil prices and realized cost savings to date, the Company has decided to reduce its capital program to $38 million (from $40 million) and spend less than forecasted funds from operations for the remainder of the year. The 2015 strategic objectives of implementing the EOR project at Mantario/Laporte, delineating the Viking play at Onward, and testing the Laporte pool extension have been achieved and we are now focused on strengthening the balance sheet. The Company implemented changes in the third quarter to improve our operating costs and administrative cost structures, both of which add to our resilience and sustainability going forward. With this limited capital program the Company is now forecasting average annual production of 4,100 – 4,200 boed.

Assuming WTI averages $45.00 US/bbl for the remainder of the year, the WTI – WCS differential averages $15.00 US/bbl, the exchange rate averages 1.32 CDN/US$ and including the benefits of our hedges, the Company forecasts funds from operations of approximately $32 million ($0.69/share) and year-end net debt of $60 million (1.8 times forecast fourth quarter funds from operations annualized).

2016 Outlook and Guidance

For 2016 Rock’s Board of Directors have approved a preliminary capital spending program of $20 million. This capital spending program focuses on delineation of the pool extension at Laporte while maintaining corporate production levels flat between 3,800 – 4,000 boed. The Company will also develop and test a number of exploration prospects. This cautious strategy is designed to maintain the balance sheet, drilling inventory and production base. Once clarity is obtained from both the commodity pricing and cost structures we will be positioned to quickly grow our production levels with our drilling inventory. We believe this is a time for financial discipline and stewardship to ensure our capital is prudently invested, not a time to harvest our inventory for production growth.

Rock’s capital program of $20 million will be focused on drilling up to 14 Laporte step-out/in-fill locations, complete four Viking wells that were drilled in 2015, drill 4 more Viking wells (in the third quarter) and test 2 – 4 exploration prospects. This program is forecast to generate funds from operations of $25 million ($0.53/share) providing $5 million to reduce yearend net debt to $55 million (1.7 times net debt to funds from operations). The forecast assumes WTI pricing is essentially equal to forward strip pricing averaging $50.00 US/bbl (Q1= WTI $45.00 US/bbl, Q2= WTI $50.00 US/bbl, Q3= WTI $50.00 US/bbl, Q4= WTI $55.00 US/bbl). It also assumes that the WTI-WCS differential is $15.00 US/bbl, the foreign exchange rate is 1.32 CDN/US, and AECO averages $2.50/GJ.

Rock has positioned itself with a low cost structure, a stable production platform with a very low decline rate (15%-20%) and a high net back production mix. Once we have confidence in an improved oil price environment we will look to expand the program to harvest the over 600 unbooked drilling locations we have assembled. We have elected to spend less than funds from operations at this point in time as we position the company to prosper in an improving price environment, however, if we were to spend all of our available funds from operations drilling additional Viking wells in the second half of the year, our production would increase to 4,500 boed by year end (over 15% growth from current levels) generating funds from operations of $28 million ($0.58/basic share) (using the same pricing assumptions under the approved budget).

We are focused on building a strong foundation and inventory of growth prospects. This disciplined approach is targeted to maintain a financially flexible organization with a long term view to value creation. As prices and costs improve, we are positioned with a solid inventory of opportunity to provide the next level of growth for our shareholders.

Production volumes and reserves are commonly expressed on a barrel of oil equivalent (“boe”) basis. All conversions in this report are derived by converting natural gas to crude oil in the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of crude oil. Certain financial values are presented on a boe basis and such measurements may not be consistent with those used by other companies. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Non-GAAP Measures

This document, including the accompanying financial statements also contain the terms “operating netback” and “total net capital expenditures” which do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities and should not be considered an alternative to or more meaningful than the prescribed GAAP measure. Management believes these measures are helpful supplementary measures of financial performance and provide users with information that is commonly used by other oil and gas companies.

Operating netback has been calculated as oil and natural gas revenues, less royalties and production and operating expenses. Management believes this is a measure of operational profitability before administrative and other financing costs. Cash netbacks are calculated as operating netbacks less general and administrative expenses before share based compensation, and interest financing costs. Readers are cautioned that these measures should not be considered an alternative to, or more meaningful than, “net loss and comprehensive loss” as determined in accordance with GAAP as a measure of the Company’s performance.

Total net capital expenditures has been calculated to include the cash impacts of capital expenditures and property dispositions, as well as non-cash capital adjustments related to the Company’s decommissioning liability and share based compensation costs. Management believes that this provides supplemental information on the total capital spending for the period.

Additional-GAAP Measures

Funds from operations

This document, including the accompanying financial statements, contain the term “funds from operations” which does not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, “cash flow from operating activities” as determined in accordance with GAAP as a measure of the Company’s performance. Funds from operations or funds from operations per share may not be comparable with the calculation of similar measures for other entities. Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and decommissioning expenditures. See “Funds from operations” section for details of this calculation. Management believes that funds from operations represent both an indicator of the Company’s performance and a funding source for ongoing operations.

Other additional GAAP measures

This document, including the accompanying financial statements also contain the terms “adjusted working capital deficiency” and “net debt” which do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities.

Working capital is defined as the difference between current assets and current liabilities. Working capital (deficiency) is the term used when the difference between current assets and current liabilities is a negative number which is quite common in the oil and gas industry. Adjusted working capital, and adjusted working capital deficiency have been calculated excluding the unrealized gains on commodity price contracts from current assets and the unrealized losses on commodity price contracts and bank debt from current liabilities. Adjusted working capital and adjusted working capital (deficiency) represent operating liquidity available to the business and are included in the definition of the additional GAAP term “net debt”.

Net debt has been calculated as bank debt plus adjusted working capital or adjusted working capital (deficiency). Net debt is used to calculate the debt-to-annualized-funds from operations ratio. Management believes these measures are useful supplementary measures of the total amount of current and long-term debt. Total capitalization is calculated as net debt plus shareholders’ equity. Management believes this measure is a useful supplementary measure of the Company’s managed capital.

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. These factors include, but are not limited to: the effect of general economic conditions, industry conditions, regulatory and taxation regimes, volatility of commodity prices, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel, any of which may cause actual results or events to differ materially from those anticipated in such forward-looking statements. .

Readers are cautioned that the foregoing lists of factors are not exhaustive. The Company believes that the expectations reflected in these forward looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this document should not be unduly relied upon. These statements speak only as of the date of this document, as the case may be. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable law.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.

The forward-looking statements contained in this document are expressly qualified by this cautionary statement. The Company does not undertake any obligation to publicly update or revise any forward-looking statements except as required by securities laws or regulations

This document may disclose drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; iii) unbooked locations; and, iv) an aggregate total of (i), (ii) and (iii). Proved undeveloped locations and probable undeveloped locations are booked and derived from Rock’s most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. as of December 31, 2014 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Rock’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of the Rock’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Rock will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Rock will actually drill wells is ultimately dependent upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.